U.S. patent application number 14/426313 was filed with the patent office on 2016-09-08 for identification of heat capacity properties of formation fluid.
This patent application is currently assigned to Halliburton Energy Services Inc.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES INC.. Invention is credited to Robert ATKINSON, Li GAO, Christopher Michael JONES, Mahaly RANDRIANAVONY, Hua XIA.
Application Number | 20160259084 14/426313 |
Document ID | / |
Family ID | 54072188 |
Filed Date | 2016-09-08 |
United States Patent
Application |
20160259084 |
Kind Code |
A1 |
XIA; Hua ; et al. |
September 8, 2016 |
IDENTIFICATION OF HEAT CAPACITY PROPERTIES OF FORMATION FLUID
Abstract
Downhole fluid sensing device is disclosed for determining heat
capacity of a formation fluid produced by a sampled subterranean
well, the sensor package having an annulus shaped, elongate body
defining a cylindrical fluid sampling space, the sensor package and
the sampling space having a common longitudinal center axis. The
elongate sensor package body has a fluid entrance port that
provides well fluid ingress into the fluid sampling space and a
fluid exit port that provides well fluid egress out of the fluid
sampling space. A heat source is coupled to the elongate sensor
package body and located along a portion of the fluid path, and the
heat source inputs heat into sampled well fluid. Finally,
temperature sensing devices (located between the fluid entrance
port and fluid exit port measure heat conducted to the sampled well
fluid, wherein each of the temperature sensing devices is radially
spaced from the heat source.
Inventors: |
XIA; Hua; (Huffman, TX)
; GAO; Li; (Katy, TX) ; ATKINSON; Robert;
(Conroe, TX) ; RANDRIANAVONY; Mahaly; (Houston,
TX) ; JONES; Christopher Michael; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES INC. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services
Inc.
Houston
TX
|
Family ID: |
54072188 |
Appl. No.: |
14/426313 |
Filed: |
March 10, 2014 |
PCT Filed: |
March 10, 2014 |
PCT NO: |
PCT/US14/22823 |
371 Date: |
March 5, 2015 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 49/081 20130101;
G01V 9/005 20130101; E21B 47/103 20200501; E21B 49/0875 20200501;
G01K 17/06 20130101; E21B 47/07 20200501 |
International
Class: |
G01V 9/00 20060101
G01V009/00; E21B 47/06 20060101 E21B047/06; E21B 49/08 20060101
E21B049/08 |
Claims
1. A downhole fluid sensing device for determining heat capacity of
a formation fluid produced by a sampled subterranean well, the
device comprising: an annulus shaped, elongate sensor package body
interiorly defining a substantially cylindrical fluid sampling
space, the elongate body and the sampling space having a common
longitudinal center axis; a fluid entrance port providing a well
fluid ingress into the fluid sampling space; a fluid exit port
providing a well fluid egress out of the fluid sampling space; an
upstream-to-downstream fluid flow path for a sampled well fluid
extending from the fluid entrance port to the fluid exit port
across the sampling space; a heat source coupled to the elongate
sensor package body and located along a portion of the fluid flow
path between the fluid entrance port and the fluid exit port for
inputting heat into the sampled well fluid; and a plurality of
temperature sensing devices coupled to the elongate sensor package
body and located between the fluid entrance port and fluid exit
port for measuring heat conducted to the sampled well fluid,
wherein each of the plurality of temperature sensing devices is
radially spaced from the heat source and wherein the measurement is
used to calculate the heat capacity of the formation fluid.
2. The downhole well fluid sensing device of claim 1, wherein the
heat source is concentrically positioned about the longitudinal
center axis of the sampling space.
3. The downhole well fluid sensing device of claim 2, wherein the
heat source is centrally positioned longitudinally within the
sampling space on the longitudinal center axis.
4. The downhole well fluid sensing device of claim 2, wherein the
heat source is positioned within the sampling space at a distance
from the longitudinal center axis.
5. The downhole well fluid sensing device of claim 2, wherein the
heat source is positioned outside the annulus shaped, elongate
sensor package body at a distance from the longitudinal center
axis.
6. The downhole well fluid sensing device of claim 5, wherein the
heat source is a coiled heating element wound about an exterior of
the annulus shaped, elongate sensor package body.
7. The downhole well fluid sensing device of claim 2, wherein the
heat source exteriorly circumscribes the annulus shaped, elongate
sensor package body.
8. The downhole well fluid sensing device of claim 1, wherein the
heat source comprises a plurality of heat inputs positioned at
different locations about the elongate sensor package body.
9. The downhole well fluid sensing device of claim 1, wherein, at
least one of the plurality of temperature sensing devices is
located between the heat source and the fluid entrance port for
measuring heat conducted upstream from the heat source and at least
one of the plurality of temperature sensing devices is located
between the heat source and the fluid exit port for measuring heat
conveyed downstream from the heat source by the sampled well fluid
flow.
10. The downhole well fluid sensing device of claim 1, wherein the
plurality of temperature sensing devices are one of: aligned, one
with the others and positioned substantially parallel to the common
longitudinal center axis of the elongate body and sampling space;
arrayed thermocouple sensors; arrayed fiber Bragg grating sensors;
optical time domain reflectometer (OTDR)-based Brillouin
distributed fiber temperature sensors; and arrayed resistivity
temperature detectors.
11. The downhole well fluid sensing device of claim 1, wherein the
heat source extends along a majority of the elongate sensor package
body.
12. A method for determining a heat capacity of formation fluid
produced by a sampled subterranean well, the method comprising:
receiving, through a fluid entrance port, a formation fluid flow in
an annulus shaped, elongate sensor package body interiorly defining
a substantially cylindrical fluid sampling space, the elongate body
and the sampling space having a common longitudinal center axis;
applying thermal energy to the fluid sampling space, wherein the
thermal energy is applied by a heat source; measuring a relative
temperature change over time at a plurality of temperature sensing
devices concentrically coupled to the elongate sensor package body,
wherein the plurality of temperature sensing devices are
longitudinally spaced along the sampling space and radially
separated from the heat source; and calculating the heat capacity
of the formation fluid based on the relative transient temperature
change.
13. The method of determining the heat capacity of a formation
fluid of claim 12 further comprising pumping the formation fluid
via a fluid exit port, out of the fluid sampling space, wherein the
fluid mass density is measured with a density meter.
14. The method of determining the heat capacity of a formation
fluid of claim 12 wherein applying thermal energy comprises
applying a pulse modulated thermal energy to the formation fluid
along a portion of the substantially cylindrical fluid sampling
space, wherein the pulse of thermal energy is applied by a heat
source.
15. The method of determining the heat capacity of a formation
fluid of claim 12, further comprising the step of: altering,
in-situ, an external heating or energy supply system, based on the
calculated thermal property for downhole hydrocarbon fluid
production optimization, wherein, during time modulated external
heat energy excitation, mufti-point thermal sensing arrays are
measured relative temperature response amplitudes, the thermal
responses are displayed in real-time, and transmitted to surface
for fluid heat capacity analyses.
16. The method of determining the heat capacity of a formation
fluid of claim 12, further comprising the step of: transmitting the
calculated thermal property to a surface computer for use altering
a drilling or production parameter.
17. The method of determining the heat capacity of a formation
fluid of claim 12, wherein the heat source is centrally positioned
within the sampling space on the longitudinal center axis.
18. The method of determining the heat capacity of a formation
fluid of claim 12, wherein the heat source is positioned within the
sampling space at a distance from the longitudinal center axis.
19. The method of determining the heat capacity of a formation
fluid of claim 12, wherein the heat source is positioned outside
the annulus shaped, elongate sensor package body at a distance from
the longitudinal center axis.
20. The method of determining the heat capacity of a formation
fluid of claim 12, wherein the pulse of thermal energy is a
modulated energy pulse with electric current.
Description
FIELD
[0001] The subject matter herein generally relates to system and
method of thermophysical property detection, and more specifically
to in-situ determination of specific heat capacities of downhole
formation fluid.
BACKGROUND
[0002] During drilling or production operations of a reservoir, the
compositions of downhole fluids often affect the drilling process
because the thermophysical properties of the downhole formation
fluids vary with pressure, temperature, and chemical composition.
Downhole formation fluids can have many properties, such as
viscosity, density, thermal conductivity, heat capacity, and mass
diffusion. Each of these properties can at least partially govern
transportation and mobility of crude oils, including high viscosity
crude oils, and can consequently impact the recovery process. High
viscosity hydrocarbon fluid production may require external heating
methods to reduce the viscosity of the fluids and enable fluid
transport from the reservoir to the well location. Efficiency of
production can be dependent upon the external heating power and
thermal energy transport within a limited time interval. Higher
heat capacity hydrocarbon fluids may require more thermal energy to
effectively reduce their viscosity. It is desirable to be able to
measure the heat capacity of formation fluids either during
wireline logging services or the production process.
[0003] Formation fluids may have similar specific heat capacities
but different viscosity, thermal conductivity, density, and mass
diffusivity. Knowing these thermophysical properties of formation
fluids can at least partially enable optimization of downhole tools
and their long-term reliability or production optimization.
Presently, most thermophysical properties of formation fluids are
typically measured from samples that are taken downhole and then
analyzed in a lab, which can take days, or even months. The
potential phase transition may reduce the accuracy of any
measurement due to the passage of time since sample collection and
environmental changes at the collection point(s) which can occur
over time. In-situ measurement of these parameters can improve
accuracy of measurement and improve tool design and well production
efficiency.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Implementations of the present technology will now be
described, by way of example only, with reference to the attached
figures, wherein:
[0005] FIG. 1 is a an elevational view of a subterranean well in
accordance with an example embodiment;
[0006] FIG. 2 is a front view of a modified reservoir description
tool (RDT) module in accordance with an example embodiment;
[0007] FIG. 3 is a partial view of a thermal-sensor package and
data acquisition system in accordance with an example
embodiment;
[0008] FIG. 4 is a partial view of a thermal-sensor package and
data acquisition system that can measure a voltage drop in
accordance with an example embodiment;
[0009] FIG. 5 is a side view of a thermal-sensor package and data
acquisition system that can measure a voltage drop in accordance
with an example embodiment;
[0010] FIG. 6 is a partial view of a thermal-sensor package and
data acquisition system that can measure temperature change in
accordance with an example embodiment;
[0011] FIGS. A. 7A-7C are example graphs of temperature response vs
time measured at 630 and 635 of FIG. 6 from high, medium, and low
heat capacity formation fluids;
[0012] FIG. 8 is an example graph of temperature response vs.
distance; and
[0013] FIG. 9 is a flowchart illustrating a method for calculating
heat capacity of produced well fluid.
DETAILED DESCRIPTION
[0014] It will be appreciated that for simplicity and clarity of
illustration, where appropriate, reference numerals have been
repeated among the different figures to indicate corresponding or
analogous elements. In addition, numerous specific details are set
forth in order to provide a thorough understanding of the
embodiments described herein. However, it will be understood by
those of ordinary skill in the art that the embodiments described
herein can be practiced without these specific details. In other
instances, methods, procedures and components have not been
described in detail so as not to obscure the related relevant
feature being described. Also, the description is not to be
considered as limiting the scope of the embodiments described
herein. The drawings are not necessarily to scale and the
proportions of certain parts have been exaggerated to better
illustrate details and features of the present disclosure.
[0015] In the following description, terms such as "upper,"
"upward," "lower," "downward," "above," "below," "downhole,"
"uphole," "longitudinal," "lateral," and the like, as used herein,
shall mean in relation to the bottom or furthest extent of, the
surrounding wellbore even though the wellbore or portions of it may
be deviated or horizontal. Correspondingly, the transverse, axial,
lateral, longitudinal, radial, etc., orientations shall mean
orientations relative to the orientation of the wellbore or tool.
Additionally, the illustrated embodiments are depicted such that
the orientation is such that the right-hand side is downhole
compared to the left-hand side.
[0016] Several definitions that apply throughout this disclosure
will now be presented. The term "coupled" is defined as connected,
whether directly or indirectly through intervening components, and
is not necessarily limited to physical connections. The connection
can be such that the objects are permanently connected or
releasably connected. The term "outside" refers to a region that is
beyond the outermost confines of a physical object. The term
"inside" indicate that at least a portion of a region is partially
contained within a boundary formed by the object. The term
"substantially" is defined to be essentially conforming to the
particular dimension, shape or other word that substantially
modifies, such that the component need not be exact. For example,
substantially cylindrical means that the object resembles a
cylinder, but can have one or more deviations from a true
cylinder.
[0017] The term "radially" means substantially in a direction along
a radius of the object, or having a directional component in a
direction along a radius of the object, even if the object is not
exactly circular or cylindrical. The term "axially" means
substantially along a direction of the axis of the object. If not
specified, the term axially is such that it refers to the longer
axis of the object and can be described as "longitudinally." The
term "temperature sensing device" means a device configured to
sense, determine, measure or derive temperature; the term can
include, but is not limited to, resistance temperature detector,
thermocouple, precision resistance thermometer, fiber Bragg grating
sensor, distributed temperature sensors, and heat sensor. The term
"reservoir description tool" means a device configurable to perform
formation tests, such as pressure, temperature, resistivity,
porosity, density, mud contamination etc. testing and/or sampling.
Formation properties testing and/or sampling includes, but is not
limited to, open hole and cased hole wireline formation properties
analyses.
[0018] The present disclosure is described in relation to a
subterranean well that is depicted schematically in FIG. 1. A
wellbore 148 is shown that has been drilled into the earth 154
using a drill bit 150. The drill bit 150 is located at the bottom,
distal end of the drill string 132 and the bit 150 and drill string
132 are being advanced into the earth 154 by the drilling rig 126.
The drilling rig 126 can be supported directly on land as shown or
on an intermediate platform if at sea. For illustrative purposes,
the top portion of the well bore 148 includes casing 134 that is
typically at least partially comprised of cement and which defines
and stabilizes the wellbore 148 after being drilled.
[0019] As shown in FIG. 1, the drill string 132 supports several
components along its length. A sensor package 152 is shown for
detecting conditions near the drill bit 150, conditions which can
include such properties as formation fluid density, temperature and
pressure, and azimuthal orientation of the drill bit 150 or string
132. In the case of directional drilling, measurement while
drilling (MWD)/logging while drilling (LWD) procedures are
supported both structurally and communicatively. Moreover, the
sensor package 152 can detect characteristics of the formation
surrounding the wellbore 148 proximate the sensor package 152 such
as resistivity and porosity. Another sensor package 136 is shown
within the cased portion of the well which can be similarly enabled
to sense nearby characteristics and conditions of the drill string,
formation fluid, casing and surrounding formation. Regardless of
which conditions or characteristics are sensed, data indicative of
those conditions and characteristics is either recorded downhole,
for instance at the processor 144 for later download, or
communicated to the surface either by wire or wirelessly. If
wirelessly, the downhole antenna 138 can be utilized to send data
to a local processor 118, via topside antenna 114. There the data
may be either processed or further transmitted along to a remote
processor via wire 116 or wirelessly via antennae 114 and 110. The
use of coiled tubing 128 and wireline 130 for downhole deployment
is also schematically indicated and contemplated in the context of
this disclosure. The possibility of an additional mode of
communication is contemplated using drilling mud 140 that is pumped
via conduit 142 to a downhole mud motor 146. Downhole, resistance
to the incoming flow of mud is modulated to send backpressure
pulses up to the surface for detection at sensor 124, and from
which representative data is sent along communication channel 120
(wired or wirelessly) to one or more processors 118, 112 for
recordation and/or processing.
[0020] In the context of the downhole environment described above,
the present disclosure enables in-situ thermal identification
techniques for reservoir and downhole formation fluid properties
analyses. Previously, these types of analyses have been
accomplished using such means as the calorimetric method for fluid
thermophysical properties analyses, but the design of these
calorimetric methods cannot withstand in-situ, downhole
conditions.
[0021] FIG. 2 is an embodiment of the present disclosure that is
part of the sensor package 152 of FIG. 1. As shown, module 200 can
include a modified reservoir description tool (RDT) module with an
in-situ formation fluid thermal identification (FTID) module 220
expanded from the indicated dashed circle 210, showing an example
location on the RDT module 200. RDT modules can have many known
components, such as a position tracking system (PTS) module 250, a
dynamic positioning system (DPS) module 251, a temperature and
pressure quartz gage sensor (QGS) module 252, a Flow-Control
Pump-Out Section (FPS) module 253, a FLDS and magnetic resonance
imaging (MRI) Lab module 254, and a mobile communications system
(MCS) module 255 which are known to persons of ordinary skill in
the art and therefore not described in detail. Finally, a first 230
end of RDT module 200 can be furthest downhole, closest to the bit,
while a second end 240 is closest to the surface. Fluid can travel
in the direction from the first end 230 to the second end 240.
[0022] FIG. 3 schematically shows more detail about the FTID module
220 of FIG. 2. As shown, the FTID module 220 can be used to measure
the heat capacity of the formation fluid, the thermal conductivity
of the formation fluid, or a combination of heat capacity and
thermal conductivity of the formation fluid, and additional
thermophysical properties can be combined to make a robust
downhole, in-situ analyses possible. The FTID module 220 can be
isolated from the general surroundings to prevent contamination
from outside sources, including unwanted heat transfer or thermal
radiation from wellbore or formation fluid. The FTID module can be
created using pipe or similar structure to form body 330 and create
a sampling space 320 that runs generally parallel with the overall
modified RDT module 200. The sampling space 320 can be annulus
shaped and can have an elongate body 330. Elongate body 330 can be
an elongate package sensor body. A pump (not shown) can be used to
create a continuous flow of formation fluid through the sampling
space 320. Heating element 310 can circumscribe the exterior of the
sampling space and can heat the sampling space 320. The heating
element 310 can be a heat pump. The change in temperature can be
measured by temperature sensing devices 340 placed along the axis
335 in the direction of flow through the sampling space 320. As
illustrated, temperature sensing devices 340 can be connected to a
thermal-sensor data acquisition system 337 which can collect and/or
store temperature data from temperature sensing device 340.
Electricity can be supplied to the system through contacts 350 and
355, in this case providing power to the heat pump 310, thereby
allowing the heat pump 310 to heat the formation fluid in sampling
space 320.
[0023] FIG. 4 shows another embodiment of the present disclosure
for determining heat capacity characteristics of the formation
fluid. As shown, the measurement device 400 can be offset and
isolated to assist in preventing contamination from outside
sources. A pump (not shown) can cause a continuous flow of
formation fluid through the sampling space 420 and body 430. The
sampling space 420 can be annulus shaped and can have an elongate
body 430. Elongate body 430 can be an thermal sensor package. In
this embodiment of the present disclosure, heating element 410 can
add heat to the formation fluids while the formation fluids flow
through the sampling space 420. Multiple temperature sensing
devices 440, 442, and 444 can measure the change in temperature of
the formation fluids imparted by the heating element 410. While
three temperature sensing devices are shown in this embodiment, the
number of temperature sensing devices can be limited by their size
and the sampling space, as well as fluid flowing velocity. Further,
the location of both the heating element 410 and the temperature
sensing devices can vary within the sampling space, as each can be
moved so that they reside in the center of the sampling space or
the temperature sensing devices can be moved outward towards the
wall, depending on the fluid velocity, fluid thermal conductivity,
and measurements desired.
[0024] With regard to the sampling space generally, the isolated
section typically can have a maximum length of 12 (twelve) inches
and though the isolated section can have a different length, such
as for example 10 (ten). However, the length can vary above and
below these lengths depending on the exact space constraints of
individualized setups. The sampling space can further entail an
outside pipe diameter of 1 (one) inch. Again, the outside diameter
of the pipe can vary depending on the space constraints of the
modified RDT module.
[0025] Heating elements or heat sources 310 and 410 can be of any
known heating method that works within the in-situ drilling
environment. The heating elements or heat sources can be, for
example, a heat pump, heating tape, heating wiring, resistance
based, laser flashing or radiant heat based, coiled induction heat
based, or any kind of heat exchange based mechanism known in the
art. The heating elements or heat sources can be placed outside the
sampling environment, as shown in FIG. 3, in the center of the
sampling environment, as shown in FIG. 4, or anywhere in between,
depending on the properties being measured. Further, the heating
elements or heat sources can extend along the majority of the
sampling space 320 or 420 or less than a majority of the sampling
space 320 or 420. The heating elements or heat sources can be
concentrically positioned about the longitudinal center axis of the
sampling space. The heating elements or heat sources can also be
positioned within the sampling space on the longitudinal center
axis or at a distance from the longitudinal center axis. Still
further, the heating elements or heat sources can be wound about or
exteriorly circumscribe an exterior of the sampling space.
[0026] The thermal sensors (340 for example) or temperature sensor
(440 for example) can be any known temperature sensing device,
examples of which are widely known and different temperature
sensing devices have different sensitivities and properties that
can be considered when choosing a specific model. Like the heating
elements, the temperature sensing devices can be placed outside the
sampling environment, in the center of the sampling environment, as
shown by FIG. 4, or anywhere in between, depending on the
properties being measured. Specifically, the temperature sensing
device can be located between the heat source and the fluid
entrance port, so that it can measure heat conducted upstream from
the heat source. Another temperature sensing device can be located
between the heat source and the fluid exit port to measure heat
conveyed downstream from the heat source by the sampled well
formation fluid flow. The temperature sensing devices can be
aligned with one another and positioned parallel or substantially
parallel to the longitudinal center axis of the elongate body and
sampling space. In one or more embodiments, the temperature sensing
devices are arrayed thermocouple sensors, fiber distributed
temperature sensors, arrayed fiber Bragg grating sensors and/or
arrayed resistivity temperature detectors.
[0027] When thermal properties are accurately known, it can enable
better accuracy of measurement and enable improved well completion
design and improved well production process. Further, well drilling
parameters can be changed. Such parameters include rate of progress
downhole, force exerted on the bit, speed of the bit, and other
parameters known to those of skill in the art. Accordingly, knowing
thermophysical properties, like heat capacity and thermal
conductivity, and calculating these properties in-situ can enable
improved drilling operation. Finally, the thermophysical properties
can be measured and stored at the RTD module 220, or transmitted,
via a telemetry system, to the surface for further calculations and
actions based thereupon.
[0028] FIG. 5 shows a further example embodiment of the present
disclosure having heating elements 510 and 515. In this case the
entire sensor package 535 is shown. The sensor package 535 can
enable the internal flow and heat input to be isolated from other
inputs beyond heating elements 510 and 515. The heating element 515
can be within the electric non-conductive formation fluid and
integrated with temperature sensing devices 540, 542, and 544.
However, the heating element 510 can be surrounded outside the
sensor package 535 for electric conductive fluid analyses.
Formation fluid can enter through a first end, entrance port 533,
and can flow from the bottom 539 of the sensor package 535 to the
top 537 of the sensor package 535 and then exit via exit port 531.
Heating element 515 can provide thermal energy via electrical
resistance, with contacts 550 and 555 providing electricity to the
heating element as well as heat pump 510, as desired. An
implementation like the one shown in FIG. 5 can enable an operator
to choose to use heating element 510, heating element 515, or a
combination of both heating elements depending on the desired
measurement(s) to be made.
[0029] In one or more embodiments, the heating element can be made
of any thermally conductive and electrically resistive material,
such as metal or can include metal. Suitable metals include, but
are not limited to, platinum (Pt), Pt-alloys, tungsten (W), and
W-alloys. A preferred heating element can be protected with an
electric insulating protecting layer for its application in the
electric conductive fluid environment. This protecting layer can be
a polymeric material, such as, but not limited to,
polytetrafluoroethylene (PTFE), polyimide (PI), polyetherketone
(PEEK), ultra-high molecular weight polyethylene, and combinations
thereof. In one or more embodiments, the protecting material can
have a thickness of 0.01 micrometer to 20 micrometers. In one or
more embodiments, the protecting polymer material such as
polyethylene can may have highly thermal conductivity.
[0030] In one or more embodiments, the thermal sensors described
herein can be any device capable of detecting a change in fluid
properties such as dynamic and steady temperatures and/or can be
capable of detecting dynamic thermal response profile along the
sensing array. Suitable thermal sensors can include thermocouple
(TC) sensors, resistivity temperature detectors (RTD), platinum
resistivity thermometors (PRT), fiber Bragg grating (FBG)-based
sensors, and/or optical time domain reflectometer (OTDR)-based
Brillouin distributed temperature sensors with centimeter spatial
resolution. In one or more embodiments, fiber sensors from Micron
Optics or from OZ Optics can be used due to their small size and
intrinsic insulating properties.
[0031] FIG. 6 shows another example embodiment of the present
disclosure that can utilize heating element 610, which runs through
the center of the sampling space 620, to heat the sampling space
620. FIGS. 7A, 7B, and 7C are example graphs showing data obtained
from the example embodiments of the present disclosure and can be
directly collected from example embodiment 600. In FIG. 7A the
formation fluid passing through the sampling space 620 can have a
high specific heat C.sub.P which produces the graph shown in FIG.
7A. High C.sub.P can be in the range from about 10 to about 15
J/(g*K). FIG. 7B shows the temperature readings of a medium C.sub.P
formation fluid flowing through sampling space 620. Medium C.sub.P
can be in the range from about 5 to about 10 J/(g*K). Finally, FIG.
7C shows temperature results of a low C.sub.P formation fluid
flowing through sampling space 620. Low C.sub.P can be in the range
from about 0.1 to about 5 J/(g*K). The ranges discussed herein are
in no way limiting and the present disclosure can operate outside
these ranges. For downhole hydrocarbon fluids, the typical specific
heat range is from 0.1 to 3 J/g*K.
[0032] As shown in FIG. 6, two temperature sensing devices 630, 635
can be used to measure temperature at two separate locations in the
sampling space 620. These temperatures are plotted on the Y-axis of
FIGS. 7A, 7B, and 7C, each against time on the X-Axis. This results
in FIG. 7A, the high C.sub.P graph, indicating that it takes longer
for the temperature at 630 to fall and longer for temperature at
635 to rise. The temperature rises at 635 for FIG. 7B, the medium
C.sub.P, and FIG. 7C, the low C.sub.P formation fluids and are
fairly similar at this resolution, with the medium C.sub.P
attaining a higher temperature and holding it longer. In FIG. 7C
the temperature falls at 630 more sharply; in other words, quicker,
for the low C.sub.P of FIG. 7C than for the medium C.sub.P shown in
FIG. 7B.
[0033] FIG. 8 shows a similar analyses based on the heating element
310 in FIG. 3. Namely, the heating element 310 can provide thermal
energy to the sampling space 320 and temperature sensing devices in
the center of the sampling space 320 can measure the change in
temperature along the axis 330. As can be seen, the formation fluid
with the higher specific heat capacity 820 has a shallower slope
and ultimately reaches a lower temperature at the end of the
thermocouple array, whereas the formational fluid with a lower
specific heat capacity reaches a higher temperature at the end of
the thermocouple array. FIG. 8 is based on the pulse modulated
current signal providing transient thermal energy, Q, that can
dissipate into the flowing fluid, the transient thermal increase in
the fluid will increase local fluid temperature, .DELTA.T. For
fluid volume, V, and density, .rho., and heat capacity, C.sub.p,
then, such thermal energy input can induce a temperature variation,
.DELTA.T(f) for a unknown fluid, and .DELTA.T(0) for a standard or
reference fluid. When keeping the same energy excitation, the
unknown heat capacity of the testing fluid is calculated as:
Q(0)=m(0)*C.sub.p(0)*.DELTA.T(0)=V*.rho.(0)*C.sub.p(0)*.DELTA.T(0)
and for unknown fluid:
Q(f)=m(f)*C.sub.P(f)*.DELTA.T(f)=V*.rho.(f)*C.sub.P)(f)*.DELTA.T(f)
Since Q(0)=Q(f), fluid heat capacity is:
C P ( f ) = .rho. ( 0 ) * .DELTA. T ( 0 ) .rho. ( f ) * .DELTA. T (
f ) ##EQU00001##
Where .rho.(f) is fluid density, which is measured with a
"densitometer" or any other known density measurement tool.
[0034] After the fluid heat capacity has been measured, it can be
used to identify gas, water, and oil. It can also be used to
identify drilling fluid (mud) and mud filtrate. Heat capacity can
also be used to analyze multi-phase fluids and to analyze
hydrocarbon gas composition. For multi-component hydrocarbons the
measured effective heat capacity is described by
C p = i = 1 n ( x i * c p ( i ) ) ##EQU00002##
Where i represents each hydrocarbon component; and effective heat
capacity is a sum of all components with its fraction of x.sub.i
under a specific pressure and temperature condition. Such an
effective heat capacity is also closely related to the molecular
weight of the hydrocarbon fluid mixture. Finally, to avoid
long-term fouling and/or scaling issues, high-frequency thermal
cycles can induce thermal stress that can assist in preventing
fouling and/or scaling issues.
[0035] Referring to FIG. 9, a flowchart is shown of a method for
determining a heat capacity of formation fluid produced by a
sampled subterranean well. The example method 900 is provided by
way of example, as there are a variety of ways to carry out the
method. The method 900 described below can be carried out using the
components illustrated in FIGS. 3 and 4 by way of example, and
various elements of these figures are referenced in explaining
example method 900. Each block shown in FIG. 9 represents one or
more processes, methods, or subroutines, carried out in the example
method 900. The example method 900 can begin at block 902
[0036] At block 902 formation fluid is received through a fluid
entrance port 533 into an annulus shaped, elongate body 320, 420
that defines a fluid sampling space 335, 435. The body and the
sampling space have a common longitudinal center axis. Then, method
900 can proceed to block 904, where thermal energy is applied to
the fluid sampling space 335, 435 by a heat source 310, 410. After
which method 900 can proceed to block 906 where the temperature
within the sampling space 335, 435 is measured by temperature
sensing devices 340, 440, 442, 444 concentrically coupled to the
body but radially separated from the heat source 310, 410. Finally,
the method 900 can proceed to block 908 where the heat capacity is
calculated for the formation fluid based on the measured
temperature changes.
[0037] Further to the environmental context of a subterranean well
depicted in FIG. 1, the downhole fluid sensing device for
determining a heat capacity of a formation fluid produced by a
sampled subterranean well that is disclosed herein can be deployed
on a drill string 132 as illustrated. Alternatively, the downhole
fluid sensing device for determining a heat capacity of a formation
fluid produced by a sampled subterranean well can be deployed on
coiled tubing 128. The downhole fluid sensing device for
determining a heat capacity of a formation fluid produced by a
sampled subterranean well can also be deployed on wireline 130.
Still further, the downhole fluid sensing device for determining a
heat capacity of a formation fluid produced by a sampled
subterranean well can be utilized in measurement while drilling
(MWD) and logging while drilling (LWD) procedures.
[0038] The embodiments shown and described above are only examples.
Many details are often found in the art such as the other features
of a logging system. Therefore, many such details are neither shown
nor described. Even though numerous characteristics and advantages
of the present technology have been set forth in the foregoing
description, together with details of the structure and function of
the present disclosure, the disclosure is illustrative only, and
changes may be made in the detail, especially in matters of shape,
size and arrangement of the parts within the principles of the
present disclosure to the full extent indicated by the broad
general meaning of the terms used in the attached claims. It will
therefore be appreciated that the embodiments described above may
be modified within the scope of the appended claims.
* * * * *